Field of the Disclosure
This disclosure generally relates to tools used in oil and gas wellbores. More specifically, the disclosure relates to downhole tools that may be run into a wellbore and useable for wellbore isolation, and systems and methods pertaining to the same. In particular embodiments, the tool may be a composite plug made of drillable materials.
Background of the Disclosure
An oil or gas well includes a wellbore extending into a subterranean formation at some depth below a surface (e.g., Earth's surface), and is usually lined with a tubular, such as casing, to add strength to the well. Many commercially viable hydrocarbon sources are found in “tight” reservoirs, which means the target hydrocarbon product may not be easily extracted. The surrounding formation (e.g., shale) to these reservoirs is typically has low permeability, and it is uneconomical to produce the hydrocarbons (i.e., gas, oil, etc.) in commercial quantities from this formation without the use of drilling accompanied with fracing operations.
Fracing is common in the industry and growing in popularity and general acceptance, and includes the use of a plug set in the wellbore below or beyond the respective target zone, followed by pumping or injecting high pressure frac fluid into the zone. The frac operation results in fractures or “cracks” in the formation that allow hydrocarbons to be more readily extracted and produced by an operator, and may be repeated as desired or necessary until all target zones are fractured.
A frac plug serves the purpose of isolating the target zone for the frac operation. Such a tool is usually constructed of durable metals, with a sealing element being a compressible material that may also expand radially outward to engage the tubular and seal off a section of the wellbore and thus allow an operator to control the passage or flow of fluids. For example, by forming a pressure seal in the wellbore and/or with the tubular, the frac plug allows pressurized fluids or solids to treat the target zone or isolated portion of the formation.
FIG. 1 illustrates a side view of a process diagram of a conventional plugging system 100 that includes use of a downhole tool 102 used for plugging a section of the wellbore 106 drilled into formation 110. The tool or plug 102 may be lowered into the wellbore 106 by way of workstring 105 (e.g., e-line, wireline, coiled tubing, etc.) and/or with setting tool 112, as applicable. The tool 102 generally includes a body 103 with a compressible seal member 122 to seal the tool 102 against an inner surface 107 of a surrounding tubular, such as casing 108. The tool 102 may include the seal member 122 disposed between one or more slips 109, 111 that are used to help retain the tool 102 in place.
In operation, forces (usually axial relative to the wellbore 106) are applied to the slip(s) 109, 111 and the body 103. As the setting sequence progresses, slip 109 moves in relation to the body 103 and slip 111, the seal member 122 is actuated, and the slips 109, 111 are driven against corresponding conical surfaces 104. This movement axially compresses and/or radially expands the compressible member 122, and the slips 109, 111, which results in these components being urged outward from the tool 102 to contact the inner wall 107. In this manner, the tool 102 provides a seal expected to prevent transfer of fluids from one section 113 of the wellbore across or through the tool 102 to another section 115 (or vice versa, etc.), or to the surface. Tool 102 may also include an interior passage (not shown) that allows fluid communication between section 113 and section 115 when desired by the user. Oftentimes multiple sections are isolated by way of one or more additional plugs (e.g., 102A).
Upon proper setting, the plug may be subjected to high or extreme pressure and temperature conditions, which means the plug must be capable of withstanding these conditions without destruction of the plug or the seal formed by the seal element. High temperatures are generally defined as downhole temperatures above 200° F., and high pressures are generally defined as downhole pressures above 7,500 psi, and even in excess of 15,000 psi. Extreme wellbore conditions may also include high and low pH environments. In these conditions, conventional tools, including those with compressible seal elements, may become ineffective from degradation. For example, the sealing element may melt, solidify, or otherwise lose elasticity, resulting in a loss the ability to form a seal barrier.
Before production operations commence, the plugs must also be removed so that installation of production tubing may occur. This typically occurs by drilling through the set plug, but in some instances the plug can be removed from the wellbore essentially intact. A common problem with retrievable plugs is the accumulation of debris on the top of the plug, which may make it difficult or impossible to engage and remove the plug. Such debris accumulation may also adversely affect the relative movement of various parts within the plug. Furthermore, with current retrieving tools, jarring motions or friction against the well casing may cause accidental unlatching of the retrieving tool (resulting in the tools slipping further into the wellbore), or re-locking of the plug (due to activation of the plug anchor elements). Problems such as these often make it necessary to drill out a plug that was intended to be retrievable.
However, because plugs are required to withstand extreme downhole conditions, they are built for durability and toughness, which often makes the drill-through process difficult. Even drillable plugs are typically constructed of a metal such as cast iron that may be drilled out with a drill bit at the end of a drill string. Steel may also be used in the structural body of the plug to provide structural strength to set the tool. The more metal parts used in the tool, the longer the drilling operation takes. Because metallic components are harder to drill through, this process may require additional trips into and out of the wellbore to replace worn out drill bits.
The use of plugs in a wellbore is not without other problems, as these tools are subject to known failure modes. When the plug is run into position, the slips have a tendency to pre-set before the plug reaches its destination, resulting in damage to the casing and operational delays. Pre-set may result, for example, because of residue or debris (e.g., sand) left from a previous frac. In addition, conventional plugs are known to provide poor sealing, not only with the casing, but also between the plug's components. For example, when the sealing element is placed under compression, its surfaces do not always seal properly with surrounding components (e.g., cones, etc.).
Downhole tools are often activated with a drop ball that is flowed from the surface down to the tool, whereby the pressure of the fluid must be enough to overcome the static pressure and buoyant forces of the wellbore fluid(s) in order for the ball to reach the tool. Frac fluid is also highly pressurized in order to not only transport the fluid into and through the wellbore, but also extend into the formation in order to cause fracture. Accordingly, a downhole tool must be able to withstand these additional higher pressures.
Additional shortcomings pertain to a downhole tool's ability to properly seal in the presence of an overly large annulus between the casing and the tool. Referring briefly to FIGS. 1A and 1B together, a side view of a conventional downhole tool prior to setting, and a close-up partial side view of the downhole tool in a set position with a sealed annulus, are shown. As illustrated, workstring 112 is used to move tool 102 to its desired downhole position. Typically the tool 102 will have a tool OD that, in combination with an ID of the casing 108, will leave a minimal annulus 190, typically in the range of about ¼″.
During the setting sequence compression of tool components occurs (e.g., cones 128, 136), which results in subsequent compression (via setting forces, Fs), and lateral or radial expansion, of the sealing element 122 away from the tool body and into the annulus 190. As shown in FIG. 1B, the sealing element 122 adequately expands into the tool annulus 190, and ultimately into sealing contact with the surface 107 of the casing 108, forming a seal 125. Because the sealing element 122 need only extrude a minimal amount, adequate amount of sealing element material remains supported by the tool 102. The seal 125 is normally strong enough to withstand 10,000 psi without any problems.
However, this is not the case when the annulus 190 exceeds a typical minimal size, such as when the annulus is in the range of about ⅜″ to about 1″ (or conceivably greater). This occurs, for example, when the size of the casing ID increases. Intuitively, the solution would be to increase the tool OD in a comparable manner so that the delta in the tool annulus is negligible or nil; however, this is not possible in situations where the casing has a narrowing or restriction of some kind.
Although there are a number of reasons as to why narrowing of casing 108 may occur, often the narrowing occurs when a “patch” or bandaid has been utilized to repair (or otherwise circumvent) damage, such as a cut or a crack, in the casing. Other instances include where an entire upper section is narrowed, such as by a heavier walled casing in the vertical section, followed by a lower section (e.g., horizontal section) after a certain depth that is wider.
Referring briefly to FIGS. 1C and 1D together, a simplified side diagram view of a downhole tool prior to passing through a narrowing in a casing, and after passing through a narrowing in a casing, respectively, are shown. As illustrated in FIG. 1C, downhole tool 102 is moving downhole through casing 108 to its desired position, but must pass through narrowing 145. As a result of narrowing 145, the casing 108 includes a first portion 147 of the casing having a first diameter 187 equivalent to that of a second portion 149 of casing. But as a result of narrowing 145, downhole tool 102 must have a tool OD 141 small enough (including with standard clearance) in order to pass through the narrowing 145. Once the tool 102 reaches its destination within the second portion 149, a large tool annulus 190 is present for which the tool 102 must be able to functionally and structurally seal off so that downhole operations can begin.
FIGS. 1E, 1F, and 1G illustrate the occurrence (sequentially) of a typical failure mode in a conventional downhole tool that needs to seal an oversized tool annulus. Specifically, FIG. 1E shows a close-up side view of the beginning of typical failure mode in a conventional downhole tool that needs to seal an oversized tool annulus; FIG. 1F shows a close-up side view of an intermediate extrusion position of a sealing element during the failure mode of the downhole tool of FIG. 1E; and FIG. 1G a close-up side view of the sealing element being entirely extruded from the downhole tool of FIG. 1E.
As shown in FIG. 1E, upon initiating the setting sequence (including resultant setting forces Fs from conical members 136 and 128), the sealing element 122 will begin to extend laterally (extrude) into the tool annulus 190. However, because the lateral distance between the tool 102 and the surface 107 of the casing is greater, more of the sealing element 122 must be extruded. Because more material must be extruded in order to traverse the distance to the casing, more compression is required, as shown in FIG. 1F.
Eventually, the extrusion distance is so great that the entire sealing element 122 is compressed and extruded in its entirety from the tool 102. In the alternative, in the event the sealing element 122 makes some minimal amount of sealing engagement with the casing, the seal 125 is weak, and a minimum amount of pressure in the annulus (or annulus pressure Fa) ‘breaks’ the seal and/or ‘flows’ the sealing element 122 away from the tool 102, as shown in FIG. 1G.
A similar effect can occur on a setting slip. That is, a setting slip will often have an outer diameter and in inner diameter, with a slip ‘thickness’ Ts therebetween. If the thickness Ts is smaller than or approaches the size of the annulus, the slip will be fully extruded and the tool cannot properly seal, nor set.
There are needs in the art for novel systems and methods for isolating wellbores in a viable and economical fashion. There is a great need in the art for downhole plugging tools that form a reliable and resilient seal against a surrounding tubular. There is also a need for a downhole tool made substantially of a drillable material that is easier and faster to drill. It is highly desirous for these downhole tools to readily and easily withstand extreme wellbore conditions, and at the same time be cheaper, smaller, lighter, and useable in the presence of high pressures associated with drilling and completion operations.
There is a need in the art for a downhole plugging tool that can properly seal a larger than normal tool annulus. There is further need for a downhole tool that can support the extrusion of a seal element in an oversized tool annulus. There is a similar need for a downhole tool that can support the setting of a slip(s) in an oversized tool annulus. This is especially desirous in instances where the tool must be small enough in OD to first pass through a narrowing in casing, and then into a larger downhole ID.